Recently there has been increasing concern about the risk of damage from induced seismicity due to hydraulic fracturing and waste injection wells. For many years it has been recognized that human activities can induce seismic events; see, for example, McGarr, A., D. Simpson, and L. Seeber, 2002, “Case Histories of Induced and Triggered Seismicity”, in Lee, W., et al., eds., “International Handbook of Earthquake and Engineering Seismology, Part A”: Academic Press. There has been some documented damage due to induced seismicity from waste injection wells. Micro-seismic events due to hydro-fracturing have been perceptible on the surface. For some recent examples of induced seismicity associated with waste injection in Arkansas see Horton, S., “Disposal of Hydrofracking Waste Fluid by Injection into Subsurface Aquifers Triggers Earthquake Swarm in Central Arkansas with Potential for Damaging Earthquakes”: Seismological Research Letters, vol. 83, no. 2, March/April, 2012, (Holland, 2013). For hydraulic fracturing in Oklahoma see Holland, A., “Earthquakes triggered by Hydraulic Fracturing in South-Central Oklahoma”: Bulletin of the Seismological Society of America, vol. 103, no. 3, pp. 1784-1792, June, 2013. For hydraulic fracturing in British Columbia see Eaton, D., et al., “Broadband microseismic observations from a Montney hydraulic treatment, northeastern B.C., Canada”: CSEG Recorder, March, 2013, pp. 44-53. Hydraulic fracturing of shales has become a widespread practice.
In addition to the widespread activity in hydraulic-fracturing of oil and gas reservoirs, there is a long-standing technology for monitoring possible damage during the acquisition of reflection seismic surveys in the oil and gas industry, particularly when using Vibroseis® as the source. These monitoring surveys have typically been concerned with peak particle velocity within selected frequency bandwidths, and sometimes with peak air-borne sound pressure levels. See Alcudia, A., et al., “Vibration and air pressure monitoring of seismic sources”: CREWES Research Report, Volume 19, 2007, University of Calgary. See also Teasdale, D., et al., “Response of Test House to Vibroseis® Vibrations and Environmental Forces”, published in GeoFrontiers 5, 2005, American Society of Civil Engineers. The prior art of monitoring Vibroseis® seismic surveys has not incorporated measurements of rotational motion to date.
There is a long standing practice of industrial vibration monitoring for activities such as quarry blasts, and construction/demolition.
Techniques for 3D and 4D seismic surveys of oil and gas fields sometimes utilize permanent deployments of 3 Component linear sensors and pressure sensors in arrays of shallow monitoring wells.
It is well understood in many fields of physical science and engineering that a complete representation of mechanical motion requires the measurement of six degrees-of-freedom. Typically this is accomplished by measuring three orthogonal linear motions, and measuring rotations around three orthogonal axes.
There is a well-established technology for measurement of the linear particle motion of seismic wavefields in the earth. Many commercial sensors exist to measure particle velocity or particle acceleration along one, or up to three, linear axes, utilizing various physical concepts to accomplish the measurements. It is most common to utilize measurements of the vertical particle motion.
There is an evolving commercial technology for measurement of the rotational particle motion of seismic wavefields in the earth. Early technology is represented by, for example, U.S. Pat. No. 2,657,373, to Piety entitled “Apparatus for Seismic Exploration”. See also U.S. Pat. No. 3,407,305, to Sterry entitled “Optical Rotational Seismometer”. See further U.S. Pat. No. 4,603,407 to Cowles entitled “Rotational Geophone”. Newer technology is represented by, for example, sensors such as those commercially offered by MetTech (model Metr-3) and Eentec (models R-1 and R-2). U.S. Pat. No. 7,516,660 to Kozlov entitled “Convective Accelerometer” describes MetTech sensor technology. U.S. Pat. No. 7,474,591 to Menard et al. entitled “Six-Component Seismic Data Acquisition System” describes technology to measure rotational data from differences of linear data.
The utility of rotational seismic measurements is appreciated in earthquake and regional crustal seismology, as discussed, for example, in Lee, W., M. Celebi, M. Todorovska, and H. Igel, guest editors, “Rotational Seismology and Engineering Applications”: Bulletin of the Seismological Society of America, vol. 99, no. 2B supplement, 2009. Further, this reference notes that rotational motion is much stronger, in at least some cases, than previously understood, and is potentially a more significant factor in damage.
Persons having skill in the art recognize that the present status of the art of seismic monitoring for risk/damage incorporates several factors, including:                An increasing need to monitor induced seismicity for increasing hydro-fracturing and waste injection well activity by use of techniques that are sensitive to all possible damage modes.        Earthquake seismology has shown that rotational energy, recorded in a few cases to date, has energy up to orders of magnitude larger than expected from standard kinematic numerical models of source mechanisms, and thus may be more important for risk/damage assessments.        
Thus, there is an unmet need to record and analyze rotational seismic data sets associated with hydraulic-fracturing, associated with waste injection wells, and also associated with Vibroseis® seismic source operations.